November 2014 marked a turning point for oil companies. Momentum from the summer’s run of $100 oil and the unforeseen but very real prosperity in previous years seemingly stopped the moment Old Man Winter first peered through his door. The price of oil had plummeted, and the industry began adjusting with the downturn.

Today, the domestic oil industry continues to struggle in a price environment largely not conducive to profitability. The Bakken in North Dakota and the Eagle Ford in South Texas were once vogue, full-steam-ahead shale plays for oil exploration. The combination of horizontal drilling and hydraulic fracturing first realized in the Barnett in North Texas unlocked their oil-rich shales, and their booms captivated the public. Tales were told of small, sleepy towns suddenly rife with life and forced to cope with an influx of opportunity and headaches as populations surged in the race to tap into the nation’s hottest tight-oil plays.

If rig counts indicate how well a region’s oil industry is doing, the early-decade darlings no longer see nearly the same hustle and bustle documented just a few years ago. Perhaps they’re now best described by boom’s dreaded converse, a single word not uncommonly heard in the nearly 160-year-old oil industry but never easily uttered by those whose passion and prosperity are interrupted by price plummets and poor economics — bust.

Drilling has slowed, wells have been left uncompleted, businesses are doing whatever it takes to stay afloat, banks have been cautious, investors have been nervous, unemployment has skyrocketed and families have suffered — all to-be-expected outcomes when it costs more to pump oil out of the ground than there is profit per barrel. And while this has been the story told about the oil industry over the past seven quarters, there's a place where, so far, key producers haven't necessarily had it so bad. It's a place that has been tested in the past yet has come through every time, that was once looked upon as a relic with little production potential left and where lessons learned long ago have positioned its companies as leaders in the oil industry. Welcome to the Permian Basin.

THE PERMIAN PLAYERS

The first well in what would come to be the nation's most-active and highest-yielding basin was spudded in Mitchell County. At 7:45 p.m. on July 20, 1920, a 2,754-foot-deep well found oil from the Westbrook field. It didn't take long for black gold to supplant white cotton as the economic driver in the Permian Basin, which spans across West Texas and southeast New Mexico. Nearly 100 years later, oil and natural gas are still kings, accounting for significant portions of the Texas and New Mexico economies.

The Permian has seen highs and lows throughout its oil-producing history. Booms and busts define the region, and the wisdom around the oil patch is that good times don't last thanks to the whims of the free market and that bad times eventually will be replaced by highs again. The commodities market is cyclical, and for producers, a century-worth of lessons forge future plans. The best are known as the Permian Players, those companies with large holdings in the Permian Basin who prosper when the industry is strong and maintain solid footing when demand for the product is low.

"I like to say the main goal of the oil business is to stay in it," says oil industry veteran Tim Dunn, CEO of CrownQuest Operating, a private exploration and production company. "We're still in it, so that's a success."

Dunn is an alumnus of Parker & Parsley Petroleum, a longtime Permian oil company that became Pioneer Natural Resources in the 1990s, another Permian Player led by the retiring Scott Sheffield. Dunn started CrownQuest in 1996 and has since led the company to become one of the premier producers in the Midland Basin, an oil-rich sub-basin in the Permian.

Fellow Parker & Parsley alumnus Tim Leach is leading the way at Concho Resources, a public company headquartered in the heart of downtown Midland whose new building boasts an enviable employee center and whose stock price seems to sit firmly in the $130s. To Leach, defining Permian Players is tricky because there are two measures: by activity level or by the volume of oil and gas being produced.

Concho isn't the only player with new headquarters. Irving-based Pioneer debuted its new Permian facility in north Midland adjacent to ClayDesta two years ago, with legendary wildcatter Clayton Williams there to cut the ribbon with Sheffield. Occidental Petroleum, the largest player, recently opened a multi-million dollar facility in west Midland not far from Chevron's new nine-figure base of Permian operations and EOG Resources' West Texas hub.

Other Permian Players include Parsley Energy, founded by Sheffield's son, who at 38 is now one of the energy business' youngest billionaires, according to the Wall Street Journal. There's also Diamondback Energy, Callon Petroleum, Energen, Laredo Petroleum and Ring Energy — just to name a few.

RSP Permian has maintained steady profitability since filing its initial public offering in January 2014. "From RSP Permian's perspective, we have been performing extremely well across the landscape of E&P companies," said Scott McNeill, RSP chief financial officer and a member of the board of directors.

To McNeill, there are a lot of reasons for RSP's survivability. "If you look at our first-quarter presentation this year, we were in the sub- $30 price range in this environment. We were only one of two companies in this industry that was generating more cash per barrel than what it was costing us to find and develop a reserve. I think that speaks to the asset quality and low-cost nature of our operations."

While companies in other basins struggle even with oil prices that mostly have stayed in the $40s and low $50s over the past few months, many producers in the Permian have survived, and stories of the state of the domestic oil industry now focus largely on the energy industry's once-overlooked upstream stalwart. It has by far the most rig activity, with Midland County alone often having more drilling activity within its 900 square miles in a given week than the in the entirety of the vast Eagle Ford and Bakken shales. Reeves County in the Delaware sub-basin is not too far behind.

What keeps the Permian Players humming despite the downturn is a combination of good bets on hedges and solid business management philosophies. Favorable geology and modern technology also help.

THE LAYER CAKE

Long before man trod his first steps upon West Texas' red dirt, the Permian Basin was a shallow sea. It hosted a diverse ecosystem whose remains after the sea disappeared became the fossil fuels extracted today. What sets the Permian apart, however, is the "layer cake" of plays packed with crude oil and natural gas. Operators largely tap into the Midland Basin's Spraberry and Wolfcamp formations, often referred together as the Wolfberry. The Delaware Basin's primary plays are the Bone Spring and Wolfcamp, or the Wolfbone. Each play has several sub-plays stacked atop each other, a geologic feature that even a non-rockhound can appreciate.

"I will never forget going to a presentation by a geologist a couple of years ago and he was describing the Permian Basin," Southern Methodist University economist Bernard "Bud" Weinstein said. "There are 12, 13 pay zones, and it's just an amazing formation that's fairly easy to crack. There's also so much knowledge about the geology because there have been operators in the Permian for 100 years. The field is very well-characterized, and the technology has improved, so it's easier to find the sweet spots."

Horizontal drilling combined with the hydraulic fracturing well-completion process has revolutionized how oil is extracted. Fracturing has been around since the 1940s and involves injecting pressure downhole to break the rock in an attempt to recover more oil and natural gas. It proved popular in the Permian's stacked plays when vertical drilling was the only option. Horizontal drilling involves steering a drilling bit laterally. The benefit is being able to access more oil and gas in a play with one horizontal hole instead of several vertical holes. The process, however, once was thought of in different terms.

"We used to drill horizontally to get to hard-to-reach places, not because we were going to produce things horizontal," Leach said when recalling when he first heard of horizontal drilling and fracturing working together. "I remember when they started drilling horizontal wells in the Barnett shale and trying to understand the geometry of how that was working and how exciting that was. I remember at the time people would say, 'Do you think that will happen in the Permian?' Most everybody said, 'Nah, that's a gas thing; it's not an oil thing.'"

Experimentation in West Texas soon followed. "I remember we talked in some of our public presentations about the first horizontal wells in the Permian and the kind of people who were drilling them," Leach said. "It was not a major oil company coming out of the lab with a new science experiment. It was an independent that was drilling horizontal to test a new idea; it was somebody who was a risk-taker in New Mexico. It was exciting."

When asked to describe just how exciting and how anxious he was to try it for himself, he replied with a wide smile: "We bought his company."

The experimentation continues as companies try different chemicals and pressures to burst through rock and keep the fissures open to extract more oil and gas. The laterals are also getting longer. A new record of 18,500 feet was set in May by oilfield services company Halliburton in Ohio's Utica Shale at a depth of more than 27,000 feet. It involved 124 frac stages over 24 days, a far cry from the early days.

"Those first wells were very short laterals with not-very-big frac jobs on them," Leach said. "We started experimenting with longer laterals and bigger frac jobs. The fluid has changed; the style of how you complete, perforate and frac has changed. It's just continuously gotten better."

For the Permian Players, being able to target specific pay zones horizontally and the sheer abundance of pay zones has benefited them, even in a downturn, because the geology is economically favorable.

“As a general rule of thumb and as a theme, the Permian Players — especially the ones with assets in core places — have weathered the storm a lot better than operators in places like the Bakken, the Eagle Ford and some of the smaller Rockies plays,” said Ben Shattuck, Wood Mackenzie principal analyst for lower 48 upstream. “What everyone tends to look at now has been the break-even prices — how low can the price of oil go for a company to drill a well and still make money instead of losing money. In a lot of places in the Permian Basin, operators can drill down as low as the mid-$30 West Texas Intermediate range and still generate a positive return, whereas for a lot of the Bakken and Eagle Ford, you need $50-plus to make that work. Are there wells that will work in the $40 range? Sure. It’s just the Permian has a greater inventory of those low-cost wells.”

In a September interview with Bloomberg, Sheffield said the break-even price in the Permian Basin in Texas is sub-$30, with break-even meaning operation costs plus a 10 percent to 15 percent return. According to analysts at JPMorgan Chase, drilling in the Permian indeed is low-cost. The break-even price in the Northern Midland Lower Spraberry is $27.17 a barrel, while the Western Glasscock Lower Spraberry is $28.82. The popular Bone Spring formation in the Delaware Basin can be drilled at $38.10 in New Mexico and $44.50 in Texas, which is very good news for the Permian Players, considering oil has stayed mostly in the $40s after recovering from a year-low of $26.21 a barrel in February.

Having good, economical assets has been critical for the Permian Players, according to oil industry analyst Stephen Schork of the popular Schork Report newsletter and a fixture on business news channels such as CNBC. “You can have the best-run, most-efficient company, but if you don’t have the assets, there’s really nothing there to exploit. I think what happened over the past five years since the economic downturn, you had a combination of well-run companies that had very strong assets and poorly run companies that had good assets. As the adage goes: A rise in tides will lift all vessels.”

Schork said the downturn has been good because companies have been forced to retrench, pare down and become more efficient, which has kept producers such as those in the Permian able to continue producing. “You need the assets, first and foremost — it’s a commodity, after all. The cheaper you can get the BTU out of the ground, the more efficient and the better off you’re going to be getting it to the market.

“That said, part of this retrenchment entails some pruning of the tree to find out where the discipline was. Those assets, mind you, will not go to waste. What you have is probably fewer competitors out there, which will become larger, more-productive, more-efficient competitors and will make companies that much stronger for the next downturn in price, which, of course, we’ll see.”

BETTING ON THE FUTURE

High-yield, economically favorable geology, however, is only part of the story for the Permian Players. Many companies had protection going into the downturn through hedges. “Hedging helps move the curve and maintain an income stream in a period of pretty dramatic volatility,” Weinstein said.

In simple terms, hedges enable producers to lock in prices for future production, often years in advance. When the oil price dropped to the $50s in November 2014, companies that hedged well had higher price guarantees than current market prices. Weinstein explains:

“Let’s say you’re an operator in the Permian, your total lifting costs are $45 a barrel, the current market price is $40 but you were smart enough to sell that production forward at $60. Even though you’re not covering your costs, you’re still making money — that’s why you hedge, but sometimes you hedge the wrong way.”

In that instance, companies lose out by selling future production lower than the market price, but the Permian Players who hedged early largely bet well.

“We were one of the most-hedged companies going into this downturn, and we’ve just continued to execute the same strategy around hedging,” Leach said. “We’ve hedged most of our proved production today, and our average price is about $55.”

CrownQuest hedged because it doesn’t have the same equity options that public companies like Concho and Pioneer have. “We’re a private company, so we don’t really have access to the public equity markets like other companies, “Dunn said. "We were very aggressive users of the hedge market. We have hedges going all the way out to 2018 that we put on before the price drop."

RSP Permian, which had gone public about 10 months before the November 2014 price drop, couldn't hedge like other Permian Players. "We entered the downturn, relatively speaking, with not as much hedging," McNeill said. "Some of that was just by the very nature of our public offering. When we went public, we had some of our non-operative partners that contributed in the time of the IPO, so we couldn't hedge their production until we owned it at the time of the offering. So we were in the midst of building our hedge book when commodity prices got hit hard."

What has helped RSP survive today was the fresh injection of public cash in 2014, which allowed the company to operate with very little debt. "We were carrying lower leverage and we had low-cost operations and well results that would stand up in a lower-commodity price environment," McNeill said. "So we had less of a need to be as well-hedged as other players out there."

However, that doesn't mean RSP has shunned hedges. "This year, we've done a lot of buying puts in order to protect the downside. We're increasing capex; we're getting more back in tune with getting our hedge book built back up."

While hedges have helped many Permian Players during the downturn, problems still remain. New technology has put record levels of oil into the market, but consumer demand for refined products hasn't kept up, thus keeping prices down. An upcoming challenge for producers might come from oil's only buyer: refineries.

DEMAND DIFFICULTIES Consumers enjoyed low gasoline prices this past summer, with record demand for the combustible fluid that makes vehicles go. There is a crude glut, and refineries have been buying as much as they can; however, a gasoline glut has formed in the process.

"It all started in the fourth quarter last year," said Wood Mackenzie senior research analyst Mark Broadbent, who specializes in the refining industry. Broadbent says the four-year run of diesel production outpacing gasoline has since shifted to gasoline and that while demand for gasoline has been high, refineries produced too much. "That yield shift went so far that, basically, it propelled gasoline stocks up a lot higher than in previous years to the point where now we're about 20 million barrels above this point in 2015.

"To put it in perspective how much of yield shift it was, even though we've had crude cuts and the crude runs have been lower in 2016 than they were in 2014 by about a couple hundred thousand barrels a day, the gasoline supply in Q2 has been higher than it was in 2015."

Schork believes this will negatively affect producers in the nation's largest oil patch. "Record demand for oil; record demand for gasoline; supplies have never been higher. What happens when that demand begins to fall off? I'm afraid this is going to leave the price of oil vulnerable and leave companies in the Permian vulnerable."

Margins have been getting tighter for refiners, Broadbent said, and the effect on upstream will depend on how hard refineries cut. "It's a very competitive environment, and potentially you could be looking at a significant period of time if refineries are stubborn and don't cut enough rate to actually work off the product."

Leach said he's not too worried because so much of what's refined is diesel, which largely is exported to other countries. Plus, the recent ability to export crude oil has opened markets worldwide. Weinstein, however, says demand abroad isn't a boon for producers at home. "We export a lot of gasoline and diesel, but export demand hasn't been as strong as anticipated because the dollar has strengthened and the global economy is not in great shape. Gasoline here in the U.S. has been in high demand during the summer driving season, but global demand growth has been quite muted, and that has limited the amount of exports of gasoline, so that means there is more in storage."

Less storage capacity is a growing issue for producers. "While there is an ample amount of gasoline and refined products, on the supply side there isn't a lot of spare capacity," RSP Permian's McNeill said. "If there is some kind of supply interruption, it also creates a situation that there's not a lot of opportunity to make up for it," adding that this year's Canadian wildfires and any "blips" in the Middle East cause wild price swings. "It's a very fragile system right now."

CrownQuest's Dunn said factors like OPEC's decision not to cut production amid low oil prices means market dislocations will take longer to "shake out." "We're probably going to see lower lows and higher highs. The world has gotten more volatile rather than less."

Weinstein says what's different today than in the past is oil is just another commodity. "We were used to price swings for corn, wheat, soybeans or copper at a time when oil might be high or low, but you didn't see the volatility you see today."

He added that OPEC, effectively the price-setter since the 1970s, has to face reality. "They cannot continue to do what they're doing. I understand Iranians say, ‘We’re just trying to ramp up to where we were before the embargo.’ No one at OPEC is breaking even at today’s prices, in a fiscal sense.”

OPEC member nations are struggling with low prices but cannot agree to output cutbacks, which continues to play a major role in why oil prices are low. North America’s newfound ability to produce mass amounts of oil and OPEC’s inability to cooperate on production levels have flooded the world with crude. Venezuela and Algeria have been especially hit hard, but all OPEC nations rely heavily on oil revenues to fund their governments and public services.

“Their lifting costs are low, but they depend on oil and gas revenues for 90 to 100 percent of their government finances,” Weinstein said. “Even the Saudis need $70 to $80 in a fiscal sense, so they just can’t keep doing what they’re doing. I say that, but the Saudis still have about $500 billion in the bank.”

Despite the oversupply and price volatility, McNeill is optimistic because history says that what goes up eventually comes down. “In the short-term, it’s a headwind. In the long-term, crude supplies won’t be able to keep up with demand.”

That optimism has been apparent in the third quarter. Oil prices have mostly held steady in the $40s, and rig counts have been on the rise, particularly in the Permian Basin. What that means in terms of the industry’s health, however, is now debated.

THE VALUE OF A RIG

In the industry, Baker Hughes is known for drill bits, well casings, frac jobs, acidizing services — pretty much everything under the sun when it comes to extracting oil. But to the general public, the longtime oilfield services company is perhaps known best for its weekly rig count statistics, which reveal how many rigs were operating in each state down to the county, the drilling trajectory of each rig and what was searched for. It’s long been an unofficial measure of the oil industry’s health, but one research firm, however, now says the rig count isn’t nearly as indicative as it once was.

Wood Mackenzie in July released a report that stated production and rig count no longer have a direct correlation. Now, it’s all about DUCs, or drilled uncompleted wells.

“At the time of our analysis, we had counted 1,700 DUCs to work through, 500 of which were in the Bakken,” said Jeanie Oudin, Wood Mackenzie senior manager of Lower 48 Research. Steep cuts in capital expenditures have producers shifting to completing already-drilled wells rather than starting fresh when seeking cash flow. DUCs are cheaper and more attractive because fewer rig commitments exist today.

“We’ve seen an extremely large build-out of DUCs,” Oudin said. “Now that the rig commitments are largely gone, operators who need the cash flow can move just toward completions and move through that DUC inventory before they return to new wells.”

Fellow Wood Mackenzie analyst Shattuck thinks that theory had a lot of validity. “If you’ve got to make the decision internally on spending a dollar on drilling and then completing versus just completing, in most cases it makes more sense to work off that backlog of uncompleted wellbores that you have.”

Shattuck said the ratio between rig count and new oil produced is very dynamic on different levels because of efficiency changes. “The smaller the rig count, the more efficient the rig fleet is, as a general rule of thumb. As you grow that rig fleet, efficiencies fall off — you have less-efficient rigs and less-efficient crews. It’s just something to be mindful of if you’re using some type of historic view to inform your future view.”

McNeill says that RSP Permian’s perspective has changed over the year. “If you would have asked me in the first quarter of this year, I would have said yes, we’ll be working off our DUCs aggressively and not doing as much drilling. But I think with commodity prices responding and coming back up from where they once were, I think we’ll be doing a lot of new drilling as well as working those DUCs down.”

For CrownQuest, “We’re not in the habit of drilling wells and leaving them uncompleted,” Dunn said. The CEO expects horizontal drilling to only increase. “With a few exceptions, the main reason people drill vertical wells now is to meet lease obligations.”

Leach said Concho has been keen on the transition to horizontal drilling for several years. “We were one of the earliest companies to start describing that we thought we were going on a transition from vertical drilling to horizontal drilling, and that was back in 2012,” he said. “Today, everything we do is horizontal.”

Lateral lengths get longer, and the number of frac stages has increased. The longer the lateral, the more oil can be extracted from a single well. With that in mind, “I believe productivity is not going to be tied to the rig count, but I think it’s more tied to the lateral feet drilled or the number of stages completed as an indicator of activity than production,” Leach said.

When it comes to locations to place wells, there has been a buying frenzy in recent months. Permian Player SM Energy bought 25,000 acres from Rock Oil for $980 million. Parsley spent $43,000 an acre in a $400 million buy from an undisclosed seller. PDC Energy bought 57,000 acres from Kimmeridge Energy for $1.5 billion. Diamondback picked up 19,000 acres from Luxe

For Concho, Leach said his company bought “the core of the core” when it spent $1.63 billion for 40,000 acres in the Midland Basin from Reliance Energy. With so many high-priced acquisitions in a downturn, is right now the time to buy?

“People always ask about the bid-ask spread and if it’s a buyer’s or a seller’s market,” oil industry veteran Leach said. “Everything I’ve ever bought in 30 years seemed expensive on the day I bought it, so I don’t tend to think of it as a buyer’s market or a seller’s market. It’s more about when can you get top quality assets and how does it fit into your portfolio.”

Leach says he didn’t buy acreage just to leave it undeveloped. “We already have so much inventory that, for us, for an acquisition to make sense, it needs to meet two criteria: It needs to be accretive to our total story in business, and then the inventory we acquired needs to move to the front of the line. We’ve got about 18,000 drilling locations. We don’t need to be buying inventory that goes to the back of the line. We need to be buying stuff that has economics that will be drilled up front. This acquisition from Reliance met both of those very easily.”

ALWAYS PREPARING

The Permian Players face more than just market volatility. There are environmentalists who want oil companies to “keep it in the ground.” There are people who want the federal government to abandon all tax treatments that oil companies receive, even if they’re the same for other industries. There are people who simply think that a wholesale shift to renewable energy will reverse climate change and make Earth a happier place.

The Players reflect.

“A lot of people give credit to the assets and where they’re located, but it takes a team of people to execute it,” RSP Permian’s McNeill said. “From a company perspective, we’re proud of the organization we’ve been able to build over the last couple of years.”

The Players adjust.

“We’ve done this for 30 years, and so we’ve been through a few of these downturns before,” Concho’s Leach said. “For us, when you look back over time, some of the best things we’ve done have been in the troughs of the cycles instead of the peaks. We think, as an organization, that you lose more sleep over doing the right thing at $140 a barrel than at $30, when you can realize gains in efficiency at the bottom of the trough.”

The Players prepare.

“One of the things that’s important is for the city and county to focus on is preparing for the next expansion. It’s important to get the road infrastructure right and to get the efficiencies in place because when we had the last boom we were pretty well busting at the seams,” said Dunn.

On the whole, Dunn says the downturn has been good for the industry. “It has given people time to trade acreage and plan infrastructure and so forth so that when expansion comes, there will be a lot more efficiency and less waste. Our city and our county, the schools and entities that serve the population hopefully are taking the same view to use the resources we have wisely and very shrewdly for more expansion.”

As Dunn says, it’s not only oil companies that drive success in the Permian Basin. “We’re all Permian Players.”